Upgrading hydrocarbon material on offshore platforms

ABSTRACT

Methods and systems for upgrading hydrocarbon on offshore platforms are described. Hydrocarbon material can be extracted from deposits under bodies of water and upgraded on offshore platforms, such as through the use of one or more nozzle reactors. The upgraded hydrocarbon material produced by the nozzle reactor, can than be transported back to shore through pipelines, in part due to the improved viscosity of the upgraded material.

This application claims priority to U.S. Provisional Patent Application No. 61/525,515, filed Aug. 19, 2011, the entirety of which is hereby incorporated by reference.

BACKGROUND

Offshore oil recovery typically entails recovering heavy oil from deposits located in the earth below bodies of water such as oceans, seas, and lakes. Typically, offshore platforms are established on or above the surface of a body of water and over the area where drilling and extraction are to take place. The offshore platforms serves as the base of operations for drilling wells, running and monitoring the oil extraction process, storing the successfully extracted material, and initiating the process of transporting the recovered material back to shore.

One main issue faced by many offshore platforms relates to the transportation of the recovered oil back to shore, where the oil can be subjected to various refinery processes in order to provide a commercially useful product. In many instances, the oil recovered from the deposits located below the sea floor is highly viscous and therefore difficult and expensive to transport back to shore via pipelines. Additionally, a market penalty is traditionally applied to oil transported ashore from offshore platforms that is still in a highly viscous state.

SUMMARY

This Summary is provided to introduce a selection of concepts in a simplified form that are further described below in the Detailed Description. This Summary, and the foregoing Background, is not intended to identify key aspects or essential aspects of the claimed subject matter. Moreover, this Summary is not intended for use as an aid in determining the scope of the claimed subject matter.

In some embodiments, an offshore hydrocarbon material recovery and transportation method is disclosed. The method includes providing an offshore platform adapted for extracting hydrocarbon material from hydrocarbon deposits located below the floor of a body of water;

extracting hydrocarbon material from a hydrocarbon deposit located below the floor of a body of water; collecting the extracted hydrocarbon material on the offshore platform; upgrading the collected hydrocarbon material on the offshore platform; and transporting the upgraded hydrocarbon material through pipelines. In some embodiments, upgrading hydrocarbon material is carried out using methods and systems described in U.S. Pat. Nos. 7,618,569, 7,927,565, or 7,988,847, or U.S. patent application Ser. No. 13/227,470.

In some embodiments, an offshore hydrocarbon material recovery and transportation system is disclosed. The offshore hydrocarbon material recovery and transportation system includes an offshore platform established over a body of water and a nozzle reactor established on the offshore platform. In some embodiments, the nozzle reactor is similar or identical to the nozzle reactor described in U.S. Pat. Nos. 7,618,569, 7,927,565, or 7,988,847, or U.S. patent application Ser. No. 13/227,470. The system can also include transportation piping for transporting upgraded hydrocarbon material back to land and a combustor adapted for generating steam and integrated with the nozzle reactor for providing steam to the nozzle reactor.

The above summarized methods and systems can advantageously provide a mechanism for upgrading collected hydrocarbon material on the offshore platform, which thereby makes transportation of the recovered material back to shore easier and more economical. While previous upgrading technologies could not be carried out on offshore platforms due to space and material constraints, the use of the nozzle reactor described herein makes upgrading on the offshore platform logistically and commercially feasible.

These and other aspects of the present system will be apparent after consideration of the Detailed Description and Figures herein. It is to be understood, however, that the scope of the invention shall be determined by the claims as issued and not by whether given subject matter addresses any or all issues noted in the Background or includes any features or aspects recited in this Summary.

BRIEF DESCRIPTION OF THE DRAWINGS

Non-limiting and non-exhaustive embodiments of the present invention, including the preferred embodiment, are described with reference to the following figures, wherein like reference numerals refer to like parts throughout the various views unless otherwise specified.

FIG. 1 is flow chart of embodiments of an offshore hydrocarbon recovery and transportation method described herein;

FIG. 2 is a cross-sectional view of a nozzle reactor suitable for use in embodiments described herein;

FIG. 3 is a cross-sectional view of a nozzle reactor suitable for use in embodiments described herein;

FIG. 4 is a cross-sectional view of a combustor suitable for use in embodiments described herein;

FIG. 5 is a block diagram illustrating embodiments of a hydrocarbon recovery and upgrading system described herein;

FIG. 6 shows a cross-sectional view of some embodiments of a nozzle reactor described herein;

FIG. 7 shows a cross-sectional view of the top portion of the nozzle reactor shown in FIG. 6;

FIG. 8 shows a cross-sectional perspective view of the mixing chamber in the nozzle reactor shown in FIG. 6; and

FIG. 9 shows a cross-sectional perspective view of the distributor from the nozzle reactor shown in FIG. 6.

DETAILED DESCRIPTION

With reference to FIG. 1, some embodiments of a method for offshore hydrocarbon material recovery and transportation method include a step 1000 of providing an offshore platform adapted for extracting hydrocarbon material from hydrocarbon deposits located below the floor of a body of water; a step 1100 of extracting hydrocarbon material from a hydrocarbon deposit located below the floor of the body of water; a step 1200 of collecting the extracted hydrocarbon material on the offshore platform; a step 1300 of upgrading the collected hydrocarbon material on the offshore platform; and a step 1400 of transporting the upgraded hydrocarbon material through pipelines. The method provides a mechanism for upgrading hydrocarbon material on the offshore platform in order to make transportation of recovered hydrocarbon back to shore easier and more economical.

Step 100 of providing an offshore platform adapted for extracting hydrocarbon material from hydrocarbon deposits located below the floor of a body of water can include providing any type of offshore platform known to those of ordinary skill in the art for extracting hydrocarbon from deposits located under bodies of water. Exemplary types of offshore platform platforms that can be used in embodiments described herein include, but are not limited to, fixed platforms, compliant towers, sea star platforms, floating production systems, tension leg platforms, subsea systems, and SPAR platforms. The offshore platform will generally include all of the standard equipment necessary for drilling production wells and extracting bitumen from deposits below the floor of the body of water. Exemplary equipment that will be included on the offshore platform includes oil rig, crane, derricks, flame boom, drilling mud module, process module, etc. In some embodiments, the offshore platform also includes a nozzle reactor for upgrading extracted hydrocarbon material on the offshore platform. While space on offshore platforms is limited, the relatively small size of the nozzle reactor allows for its inclusion on the offshore platform with only minor adjustments to the general layout of equipment on the offshore platform.

The offshore platform provided in step 100 is positioned over an area of the floor of the body of water in which deposits of bituminous material exist. Deposits of bituminous material can be identified by any techniques known to those of ordinary skill in the art, including remote sensing, seismic exploration, magnetotellurics and some other geological and geophysiscs techniques.

Step 1100 of extracting hydrocarbon material from a hydrocarbon deposit located below the floor of the body of water can be carried out using any hydrocarbon extraction method known to those of ordinary skill in the art and which can be carried out on an offshore platform. Generally, the extraction process entails drilling a well in the deposit below the body of water and then injecting various materials to aid in the recovery of the hydrocarbon material. The materials injected into the well help to lower the viscosity of the hydrocarbon material and cause it to flow towards the well, where it can then be pumped up to the offshore platform. Various materials can be used to aid in the recovery process, including steam and various solvents known to reduce the viscosity of the hydrocarbon and/or dissolve the hydrocarbon material.

The hydrocarbon material extracted from the deposit under the body of water can include various hydrocarbon components, including bitumen and asphaltenes. In some embodiments, the extracted hydrocarbon material will include predominantly heavy hydrocarbon molecules, including hydrocarbon molecules having a boiling point temperature above 1,050 F. In some embodiments, the viscosity of the extracted hydrocarbon material will be greater than 25000 cSt @ 20 deg C.

In step 1200, the extracted hydrocarbon material is collected on the offshore platform. As mentioned above, the hydrocarbon material that is made to flow towards the drilled wells can be pumped up to the offshore platform, where it can then be collected and stored in storage vessels included on the offshore platforms. Alternatively or in conjunction with storing the collected hydrocarbon material on offshore platform, the collected hydrocarbon material can be fed directly into processing equipment included on the offshore platforms, such as nozzle reactors. In some embodiments, the processing equipment included on the offshore platform is designed to have a capacity that matches or exceeds that rate at which bitumen is extracted and collected on the offshore platform in order to minimize or eliminate the need for storage vessels on the offshore platforms.

In step 1300, the collected hydrocarbon material on the offshore platform is upgraded on the offshore platform. Any technique known to those or ordinary skill in the art can be used to carry out the upgrading of the collected hydrocarbon material. In some embodiments, the techniques suitable for upgrading will be limited by space and material constraints on the offshore platform. Thus, in a preferred embodiment, upgrading is carried out in a nozzle reactor. Nozzle reactors can be suitable for use on offshore platforms due to their relatively small size and the ability to provide materials needed to carry out nozzle reactor upgrading from process integration and/or through the use of water from the body of water on which the offshore platform is established.

In some embodiments, the nozzle reactor provided on the offshore platform and used to carry out step 1300 is similar or identical to embodiments of the nozzle reactor described in U.S. Pat. Nos. 7,618,569, 7,927,565, or 7,988,847, or U.S. patent application Ser. No. 13/227,470. The nozzle reactor described in the '597 patent generally receives a cracking material and accelerates it to a supersonic speed via a converging and diverging injection passage. Collected hydrocarbon material is injected into the nozzle reactor adjacent the location the cracking material exits the injection passage and at a direction transverse to the direction of the cracking material. The interaction between the cracking material and the hydrocarbon material results in the cracking of the hydrocarbon material into a lighter hydrocarbon material.

With reference to FIG. 2, a nozzle reactor suitable for use in embodiments described herein, indicated generally at 10, has an injection end 12, a tubular reactor body 14 extending from the injection end 12, and an ejection port 13 in the reactor body 14 opposite its injection end 12. The injection end 12 includes an injection passage 15 extending into the interior reactor chamber 16 of the reactor body 14. The central axis A of the injection passage 15 is coaxial with the central axis B of the reactor chamber.

With continuing reference to FIG. 2, the injection passage 15 has a circular diametric cross-section and, as shown in the axially-extending cross-sectional view of FIG. 2, opposing inwardly curved side wall portions 17, 19 (i.e., curved inwardly toward the central axis A of the injection passage 15) extending along the axial length of the injection passage 15. In certain embodiments, the axially inwardly curved side wall portions 17, 19 of the injection passage 15 allow for a higher speed of injection when passing through the injection passage 15 into the reactor chamber 16.

In certain embodiments, the side wall of the injection passage 15 can provide one or more among: (i) uniform axial acceleration of material passing through the injection nozzle passage; (ii) minimal radial acceleration of such material; (iii) a smooth finish; (iv) absence of sharp edges; and (v) absence of sudden or sharp changes in direction. The side wall configuration can render the injection passage 15 substantially isentropic. These latter types of side wall and injection passage 15 features can be, among other things, particularly useful for pilot plant nozzle reactors of minimal size.

A material feed passage or channel 18 extends from the exterior of the junction of the injection end 12 and the tubular reactor body 14 toward the reaction chamber 16 transversely to the axis B of the interior reactor chamber 16. The material feed passage 18 penetrates an annular material feed port 20 adjacent the interior reactor chamber wall 22 at the end 24 of the interior reactor chamber 16 abutting the injection end 12. The material feed port 20 includes an annular, radially extending chamber feed slot 26 in material-injecting communication with the interior reactor chamber 16. The material feed port 20 is thus configured to inject feed material: (i) at about a 90° angle to the axis of travel of cracking material injected from the injection nozzle passage 15; (ii) around the entire circumference of a cracking material injected through the injection passage 15; and (iii) to impact the entire circumference of the free cracking material stream virtually immediately upon its emission from the injection passage 15 into the reactor chamber 16.

The annular material feed port 20 may have a U-shaped or C-shaped cross-section among others. In certain embodiments, the material feed port may be open to the interior reactor chamber 16, with no arms or barrier in the path of fluid flow from the material feed passage 18 toward the interior reactor chamber 16. The junction of the material feed port 20 and material feed passage 18 can have a radiused cross-section.

In alternative embodiments, the material feed passage 18, associated feed port 20, and/or injection passage 15 may have differing orientations and configurations, and there can be more than one material feed port and associated structure. Similarly, in certain embodiments the injection passage 15 may be located on or in the side 23 of the reactor chamber 16 (and if desired may include an annular cracking material port) rather than at the injection end 12 of the reactor chamber 16; and the material feed port 20 may be non-annular and located at the injection end 12 of the reactor chamber 16.

In the embodiment of FIG. 2, the interior reactor chamber 16 can be bounded by stepped, telescoping tubular side walls 28, 30, 32 extending along the axial length of the reactor body 14. In certain embodiments, the stepped side walls 28, 30, 32 are configured to: (i) allow a free jet of injected cracking material, such as superheated steam, natural gas, carbon dioxide, or other material, to travel generally along and within the conical jet path C generated by the ejection nozzle passage 15 along the axis 13 of the reactor chamber 16, while (ii) reducing the size or involvement of back flow areas, e.g., 34, 36, outside the conical or expanding jet path C, thereby forcing increased contact between the high speed cracking material stream within the conical path C and feed material, such as heavy hydrocarbons, injected through the feed port 20.

As indicated by the drawing gaps 38, 40 in the embodiment of FIG. 2, the tubular reactor body 14 has an axial length (along axis B) that is much greater than its width. In the FIG. 2 embodiment, exemplary length-to-width ratios are typically in the range of 2 to 4 or more.

With reference now to FIG. 3 and the particular embodiment shown therein, the reactor body 44 includes a generally tubular central section 46 and a frustoconical ejection end 48 extending from the central section 46 opposite an insert end 50 of the central section 46, with the insert end 50 in turn abutting the injection nozzle 52. The insert end 50 of the central section 46 consists of a generally tubular central body 51. The central body 51 has a tubular material feed passage 54 extending from the external periphery 56 of the insert end 50 radially inwardly to injectingly communicate with the annular circumferential feed port depression or channel 58 in the otherwise planar, radially inwardly extending portion 59 of the axially stepped face 61 of the insert, end 50. The inwardly extending portion 59 abuts the planar radially internally extending portion 53 of a matingly stepped face 55 of the injection nozzle 52. The feed port channel 58 and axially opposed radially internally extending portion 53 of the injection nozzle 52 cooperatively provide an annular feed port 57 disposed transversely laterally, or radially outwardly, from the axis A of a preferably non-linear injection passage 60 in the injection nozzle 52.

The tubular body 51 of the insert end SD is secured within and adjacent the interior periphery 64 of the reactor body 44. The mechanism for securing the insert end 50 in this position may consist of an axially-extending nut-and-bolt arrangement (not shown) penetrating co-linearly mating passages (not shown) in: (i) an upper radially extending lip 66 on the reactor body 44; (ii) an abutting, radially outwardly extending thickened neck section 68 on the insert end 50; and (iii) in turn, the abutting injector nozzle 52. Other mechanisms for securing the insert end 50 within the reactor body 44 may include a press fit (not shown) or mating threads (not shown) on the outer periphery 62 of the tubular body 51 and on the inner periphery 64 of the reactor body 44. Seals, e.g., 70, may be mounted as desired between, for example, the radially extending lip 66 and the abutting the neck section 68 and the neck section 68 and the abutting injector nozzle 52.

The non-linear injection passage 60 has, from an axially-extending cross-sectional perspective, mating, radially inwardly curved opposing side wall sections 72, 74 extending along the axial length of the non-linear injection passage 60. The entry end 76 of injection passage 60 provides a rounded circumferential face abutting an injection feed tube 78, which can be bolted (not shown) to the mating planar, radially outwardly extending distal face 80 on the injection nozzle 52.

In the embodiment of FIG. 2, the nozzle passage 60 is a DeLaval type of nozzle and has an axially convergent section 82 abutting an intermediate relatively narrower throat section 84, which in turn abuts an axially divergent section 86. The nozzle passage 60 also has a circular diametric cross-section (i.e., in cross-sectional view perpendicular to the axis of the nozzle passage) all along its axial length. In certain embodiments, the nozzle passage 60 may also present a somewhat roundly curved thick 82, less curved thicker 84, and relatively even less curved and more gently sloped relatively thin 86 axially extending cross-sectional configuration from the entry end 76 to the injection end 88 of the injection passage 60 in the injection nozzle 52.

The nozzle passage 60 can thus be configured to present a substantially isentropic or frictionless configuration for the injection nozzle 52. This configuration may vary, however, depending on the application involved in order to yield a substantially isentropic configuration for the application.

The injection passage 60 is formed in a replaceable injection nozzle insert 90 press-fit or threaded into a mating injection nozzle mounting passage 92 extending axially through an injection nozzle body 94 of the injection nozzle 52. The injection nozzle insert 90 is preferably made of hardened steel alloy, and the balance of the nozzle reactor 100 components other than seals, if any, are preferably made of steel or stainless steel.

In the particular embodiment shown in FIG. 2, the narrowest diameter D within the injection passage is 140 mm. The diameter E of the ejection passage opening 96 in the ejection end 48 of the reactor body 44 is 2.2 meters. The axial length of the reactor body 44, from the injection end 88 of the injector passage 60 to the ejection passage opening 96, is 10 meters.

The interior peripheries 89, 91 of the insert end 50 and the tubular central section 46, respectively, cooperatively provide a stepped or telescoped structure expanding radially outwardly from the injection end 88 of the injection or injector passage 60 toward the frustoconical end 48 of the reactor body 44. The particular dimensions of the various components, however, will vary based on the particular application for the nozzle reactor, generally 100. Factors taken into account in determining the particular dimensions include the physical properties of the cracking gas (density, enthalpy, entropy, heat capacity, etc.) and the pressure ratio from the entry end 76 to the injection end 88 of the injector passage 60.

In certain embodiments having one or more non-linear cracking gas injection passages, e.g., 60, such as the convergent/divergent configuration of FIG. 2, the pressure differential can yield a steady increase in the kinetic energy of the cracking material as it moves along the axial length of the cracking gas injection passage(s) 60. The cracking material may thereby eject from the ejection end 88 of the injection passage 60 into the interior of the reactor body 44 at supersonic speed with a commensurately relatively high level of kinetic energy. In these embodiments, the level of kinetic energy of the supersonic discharge cracking material is therefore greater than can be achieved by certain prior art straight-through.

Feed stock is injected into the material feed passage 54 and then through the mating annular feed port 57. The feed stock thereby travels radially inwardly to impact a transversely (i.e., axially) traveling high speed cracking mateiral (for example, steam, natural gas, carbon dioxide or other gas not shown) virtually immediately upon its ejection from the ejection end 88 of the injection passage 60. The collision of the radially injected feed stock with the axially traveling high speed steam jet delivers kinetic and thermal energy to the feed stock. The applicants believe that this process may continue, but with diminished intensity and productivity, through the length of the reactor body 44 as injected feed stock is forced along the axis of the reactor body 44 and yet constrained from avoiding contact with the jet stream by the telescoping interior walls, e.g., 89, 91 101, of the reactor body 44. Depending on the nature of the feed stock and its pre-feed treatment, differing results can be procured, such as cracking of heavy hydrocarbons, including bitumen, into lighter hydrocarbons.

FIGS. 6 and 7 show cross-sectional views of another embodiment of a nozzle reactor 100 suitable for use in the methods described herein. The nozzle reactor 100 includes a head portion 102 coupled to a body portion 104. A main passage 106 extends through both the head portion 102 and the body portion 104. The head and body portions 102, 104 are coupled together so that the central axes of the main passage 106 in each portion 102, 104 are coaxial so that the main passage 106 extends straight through the nozzle reactor 100.

It should be noted that for purposes of this disclosure, the term “coupled” means the joining of two members directly or indirectly to one another. Such joining may be stationary in nature or movable in nature. Such joining may be achieved with the two members or the two members and any additional intermediate members being integrally formed as a single unitary body with one another or with the two members or the two members and any additional intermediate member being attached to one another. Such joining may be permanent in nature or alternatively may be removable or releasable in nature.

The nozzle reactor 100 includes a feed passage 108 that is in fluid communication with the main passage 106. The feed passage 108 intersects the main passage 106 at a location between the portions 102, 104. The main passage 106 includes an entry opening 110 at the top of the head portion 102 and an exit opening 112 at the bottom of the body portion 104. The feed passage 108 also includes an entry opening 114 on the side of the body portion 104 and an exit opening 116 that is located where the feed passage 108 meets the main passage 106.

During operation, the nozzle reactor 100 includes a reacting fluid that flows through the main passage 106. The reacting fluid enters through the entry opening 110, travels the length of the main passage 106, and exits the nozzle reactor 100 out of the exit opening 112. A feed material flows through the feed passage 108. The feed material enters through the entry opening 114, travels through the feed passage 106, and exits into the main passage 108 at exit opening 116.

The main passage 106 is shaped to accelerate the reacting fluid. The main passage 106 may have any suitable geometry that is capable of doing this. As shown in FIGS. 6 and 7, the main passage 106 includes a first region having a convergent section 120 (also referred to herein as a contraction section), a throat 122, and a divergent section 124 (also referred to herein as an expansion section). The first region is in the head portion 102 of the nozzle reactor 100.

The convergent section 120 is where the main passage 106 narrows from a wide diameter to a smaller diameter, and the divergent section 124 is where the main passage 106 expands from a smaller diameter to a larger diameter. The throat 122 is the narrowest point of the main passage 106 between the convergent section 120 and the divergent section 124. When viewed from the side, the main passage 106 appears to be pinched in the middle, making a carefully balanced, asymmetric hourglass-like shape. This configuration is commonly referred to as a convergent-divergent nozzle or “con-di nozzle”.

The convergent section of the main passage 106 accelerates subsonic fluids since the mass flow rate is constant and the material must accelerate to pass through the smaller opening. The flow will reach sonic velocity or Mach 1 at the throat 122 provided that the pressure ratio is high enough. In this situation, the main passage 106 is said to be in a choked flow condition.

Increasing the pressure ratio further does not increase the Mach number at the throat 122 beyond unity. However, the flow downstream from the throat 122 is free to expand and can reach supersonic velocities. It should be noted that Mach 1 can be a very high speed for a hot fluid since the speed of sound varies as the square root of absolute temperature. Thus the speed reached at the throat 122 can be far higher than the speed of sound at sea level.

The divergent section 124 of the main passage 106 slows subsonic fluids, but accelerates sonic or supersonic fluids. A convergent-divergent geometry can therefore accelerate fluids in a choked flow condition to supersonic speeds. The convergent-divergent geometry can be used to accelerate the hot, pressurized reacting fluid to supersonic speeds, and upon expansion, to shape the exhaust flow so that the heat energy propelling the flow is maximally converted into kinetic energy.

The flow rate of the reacting fluid through the convergent-divergent nozzle is isentropic (fluid entropy is nearly constant). At subsonic flow the fluid is compressible so that sound, a small pressure wave, can propagate through it. At the throat 122, where the cross sectional area is a minimum, the fluid velocity locally becomes sonic (Mach number=1.0). As the cross sectional area increases the gas begins to expand and the gas flow increases to supersonic velocities where a sound wave cannot propagate backwards through the fluid as viewed in the frame of reference of the nozzle (Mach number>1.0).

The main passage 106 only reaches a choked flow condition at the throat 122 if the pressure and mass flow rate is sufficient to reach sonic speeds, otherwise supersonic flow is not achieved and the main passage will act as a venturi tube. In order to achieve supersonic flow, the entry pressure to the nozzle reactor 100 should be significantly above ambient pressure.

The pressure of the fluid at the exit of the divergent section 124 of the main passage 106 can be low, but should not be too low. The exit pressure can be significantly below ambient pressure since pressure cannot travel upstream through the supersonic flow. However, if the pressure is too far below ambient, then the flow will cease to be supersonic or the flow will separate within the divergent section 124 of the main passage 106 forming an unstable jet that “flops” around and damages the main passage 106. In one embodiment, the ambient pressure is no higher than approximately 2-3 times the pressure in the supersonic gas at the exit.

The supersonic reacting fluid collides and mixes with the feed material in the nozzle reactor 100 to produce the desired reaction. The high speeds involved and the resulting collision produces a significant amount of kinetic energy that helps facilitate the desired reaction. The reacting fluid and/or the feed material may also be pre-heated to provide additional thermal energy to react the materials.

The nozzle reactor 100 may be configured to accelerate the reacting fluid to at least approximately Mach 1, at least approximately Mach 1.5, or, desirably, at least approximately Mach 2. The nozzle reactor may also be configured to accelerate the reacting fluid to approximately Mach 1 to approximately Mach 7, approximately Mach 1.5 to approximately Mach 6, or, desirably, approximately Mach 2 to approximately Mach 5.

As shown in FIG. 7, the main passage 106 has a circular cross-section and opposing converging side walls 126, 128. The side walls 126, 128 curve inwardly toward the central axis of the main passage 106. The side walls 126, 128 form the convergent section 120 of the main passage 106 and accelerate the reacting fluid as described above.

The main passage 106 also includes opposing diverging side walls 130, 132. The side walls 130, 132 curve outwardly (when viewed in the direction of flow) away from the central axis of the main passage 106. The side walls 130, 132 form the divergent section 124 of the main passage 106 that allows the sonic fluid to expand and reach supersonic velocities.

The side walls 126, 128, 130, 132 of the main passage 106 provide uniform axial acceleration of the reacting fluid with minimal radial acceleration. The side walls 126, 128, 130, 132 may also have a smooth surface or finish with an absence of sharp edges that may disrupt the flow. The configuration of the side walls 126, 128, 130, 132 renders the main passage 106 substantially isentropic.

The feed passage 108 extends from the exterior of the body portion 104 to an annular chamber 134 formed by head and body portions 102, 104. The portions 102, 104 each have an opposing cavity so that when they are coupled together the cavities combine to form the annular chamber 134. A seal 136 is positioned along the outer circumference of the annular chamber 134 to prevent the feed material from leaking through the space between the head and body portions 102, 104.

It should be appreciated that the head and body portions 102, 104 may be coupled together in any suitable manner. Regardless of the method or devices used, the head and body portions 102, 104 should be coupled together in a way that prevents the feed material from leaking and withstands the forces generated in the interior. In one embodiment, the portions 102, 104 are coupled together using bolts that extend through holes in the outer flanges of the portions 102, 104.

The nozzle reactor 100 includes a distributor 140 positioned between the head and body portions 102, 104. The distributor 140 prevents the feed material from flowing directly from the opening 141 of the feed passage 108 to the main passage 106. Instead, the distributor 140 annularly and uniformly distributes the feed material into contact with the reacting fluid flowing in the main passage 106.

As shown in FIG. 9, the distributor 140 includes an outer circular wall 148 that extends between the head and body portions 102, 104 and forms the inner boundary of the annular chamber 134. A seal or gasket may be provided at the interface between the distributor 140 and the head and body portions 102, 104 to prevent feed material from leaking around the edges.

The distributor 140 includes a plurality of holes 144 that extend through the outer wall 148 and into an interior chamber 146. The holes 144 are evenly spaced around the outside of the distributor 140 to provide even flow into the interior chamber 146. The interior chamber 146 is where the main passage 106 and the feed passage 108 meet and the feed material comes into contact with the supersonic reacting fluid.

The distributor 140 is thus configured to inject the feed material at about a 90° angle to the axis of travel of the reacting fluid in the main passage 106 around the entire circumference of the reacting fluid. The feed material thus forms an annulus of flow that extends toward the main passage 106. The number and size of the holes 144 are selected to provide a pressure drop across the distributor 140 that ensures that the flow through each hole 144 is approximately the same. In one embodiment, the pressure drop across the distributor is at least approximately 2000 pascals, at least approximately 3000 pascals, or at least approximately 5000 pascals.

Referring to FIG. 8, holes 144 are shown having a circular cross-section. Circular holes 144 are suitable for effective nozzle reactor operation when the nozzle reactor is relatively small and handling production capacities less than, e.g., 1,000 bbl/day. At such production capacities, the feed material passing through the circular holes will break up into the smaller droplet size necessary for efficient mixing or shearing with the reacting fluid.

The distributor 140 includes a wear ring 150 positioned immediately adjacent to and downstream of the location where the feed passage 108 meets the main passage 106. The collision of the reacting fluid and the feed material causes a lot of wear in this area. The wear ring is a physically separate component that is capable of being periodically removed and replaced.

As shown in FIG. 9, the distributor 140 includes an annular recess 152 that is sized to receive and support the wear ring 150. The wear ring 150 is coupled to the distributor 140 to prevent it from moving during operation. The wear ring 150 may be coupled to the distributor in any suitable manner. For example, the wear ring 150 may be welded or bolted to the distributor 140. If the wear ring 150 is welded to the distributor 140, as shown in FIG. 8, the wear ring 150 can be removed by grinding the weld off. In some embodiments, the weld or bolt need not protrude upward into the interior chamber 146 to a significant degree.

The wear ring 150 can be removed by separating the head portion 102 from the body portion 104. With the head portion 102 removed, the distributor 140 and/or the wear ring 150 are readily accessible. The user can remove and/or replace the wear ring 150 or the entire distributor 140, if necessary.

As shown in FIGS. 6 and 7, the main passage 106 expands after passing through the wear ring 150. This can be referred to as expansion area 160 (also referred to herein as an expansion chamber). The expansion area 160 is formed largely by the distributor 140, but can also be formed by the body portion 104.

Following the expansion area 160, the main passage 106 includes a second region having a converging-diverging shape. The second region is in the body portion 104 of the nozzle reactor 100. In this region, the main passage includes a convergent section 170 (also referred to herein as a contraction section), a throat 172, and a divergent section 174 (also referred to herein as an expansion section). The converging-diverging shape of the second region differs from that of the first region in that it is much larger. In one embodiment, the throat 172 is at least 2-5 times as large as the throat 122.

The second region provides additional mixing and residence time to react the reacting fluid and the feed material. The main passage 106 is configured to allow a portion of the reaction mixture to flow backward from the exit opening 112 along the outer wall 176 to the expansion area 160. The backflow then mixes with the stream of material exiting the distributor 140. This mixing action also helps drive the reaction to completion.

As noted above, the cracking material used to upgrade the collected hydrocarbon material in the nozzle reactor can be steam. In some embodiments where steam is used as a cracking material, steam for use in the nozzle reactor can be generated using a combustor. Generally speaking, steam is generated from a combustor by injecting an air stream and a fuel stream into a combustor and producing a combustion flame in a combustion chamber and injecting atomized water into the combustion chamber and forming steam. This method of steam generation beneficially provides an alternative to boilers for steam generation. In addition to being less cost-intensive than boilers, the method also allows for the use of treated water in steam generation, which further makes the method more cost effective than steam generated by boilers. Other benefits of the method over the use of boilers for steam generation include the elimination of a flue gas by-product and ability to take advantage of produced streams from other processes for better process integration.

In the first step of generating steam from a combustor, an air stream and a fuel stream are injected into a combustor. The reaction of the fuel stream and the air stream creates a combustion flame in the combustion chamber of the combustor. An objective of this step is to provide a heat from the reaction between the fuel stream and the air stream to convert water injected into the combustion chamber into steam. The reaction between the air stream and the fuel stream can also produce additional materials that can be used as motive fluids in upgrading processes such as cracking of hydrocarbon material in a nozzle reactor.

Any air stream capable of being reacted with a fuel stream in a combustor to produce an exothermic reaction can be used. In some embodiments, the air stream is standard air from the surrounding environment. The air stream will typically include a content of O₂ of N₂. In some embodiments, the air stream includes an O₂ content in the range of from 18 to 21%. In some embodiments, the air is turbine air, which can include a depleted amount of oxygen (such as less than 14 vol % oxygen). In some embodiments, the air is enriched air, such as air having from 22 to 28 vol % oxygen). In some embodiments, the air is industrial oxygen, such as from 90 to 99 vol % oxygen). Industrial oxygen can be beneficial in that the removal of nitrogen can results in the creation of cracking material free of nitrogen. This, in turn, can result in cleaner and combustible fuel gas being produced by the nozzle reactor.

The air stream injected into the combustor can be at a raised temperature and pressure to facilitate the reaction in the combustor. In some embodiments, the air stream has a temperature in the range of from 1,350 to 1,500° F. and the air stream can have a pressure of from 400 to 550 psig. When the source of the air stream does not provide air at the desired temperature and/or pressure, steps can be taken to adjust the temperature and/or pressure to within the desired ranges. Any suitable techniques for heating and/or pressurizing the air stream can be used. For example, the air stream can be run through a compressor to raise the pressure to within a suitable range.

In instances where a turbine, such as a gas turbine, is present on the offshore platform, the exhaust from the turbine can be used as the air stream. Use of the turbine exhaust as the air stream can be useful because turbine exhaust typically has a raised temperature and pressure and has the desired O₂ content. Accordingly, use of turbine exhaust can eliminate or reduce the need to heat and pressurize the air stream prior to injecting the air stream into the combustor. In one example, turbine exhaust having an O₂ content of 14% is provided at a temperature of 1,400° F. and a pressure of 450 psig, meaning that the exhaust from the turbine can be directly injected into the combustor with the need for any pre-treatment. Such process integration lowers the overall cost of generating steam.

The turbine integrated into process can include the turbine used to generate power for the entire offshore platform, such as the power needed for all rotating machines, powered electrical units, and accommodations (lights, air conditioning, etc.). Such turbines can be natural gas or fuel gas powered turbines. The steam generation capacity can be calculated based on the exhaust gas temperature and flow rate from the turbine designed to power the off-shore platform, which in turn can be used to calculate the capacity of the nozzle reactor. An example of a commercially available gas turbine that can be used on the off-shore platform and integrated into the process is the Centaur 50 manufactured by Solar Turbines of California, USA. The Centaur 50 is a natural gas fired turbine that generates roughly 5 MW of electrical power.

In some embodiments, the exhaust from a custom engine can be used as the air stream. The custom engine can include only an air compressor and a combustor section. The exhaust from such a custom engine can be used in the combustor to generate steam in the same manner as described above when exhaust from a turbine is used in the combustor.

Any low molecular weight fuel stream capable of being reacted with an air stream in a combustor to produce an exothermic reaction without coke formation can be used. Exemplary fuels streams include natural gas, methane, and ethane.

The source of the fuel stream is generally not limited, and can include both fuel provided independently of any other processes being performed on the offshore platform and fuel produced by other processes being performed on the offshore platform.

The air stream and the fuel stream are injected into a combustor to react and provide an exothermic reaction. Any combustor suitable for reacting the air stream and fuel stream to provide an exothermic reaction can be used. With reference to FIG. 4, a typical combustor 200 suitable for use in the methods described herein will include a fuel injector 210, an air stream injector 220, an igniter 230, a combustion chamber 240 where the exothermic reaction takes place and where the combustion flame is produced, and a casing 250 housing all of the components of the combustor. The air and fuel stream are injected into the combustor, where the two materials react, give off heat, and with the aid of the igniter, provide a combustion flame. A basic example of the reaction that can take place inside the combustion zone when the fuel stream is methane is shown below:

CH₄+0.5O₂→CO+2H₂, h=−36 kJ/mol

In addition to CO and H₂, other reaction products that can be formed by the reaction of the fuel stream and the air stream in the combustor include CO₂, N₂ and H₂O.

The amount of the fuel stream and air stream injected into the combustor can include any rates suitable for reacting the two streams and that can be handled by the combustor used. In some embodiments, the stoichiometric ratio of fuel to air is greater than 1 (i.e., fuel rich). Typical combustion products for the reaction of air and natural gas (no additional steam added) at various stoichiometric ratios of fuel to air (Φ) are provided in Table 1.

TABLE 1 Φ = 1.1 Φ = 1.3 Φ = 1.5 Wet (%) Wet (%) Wet (%) N2 69 N2 66 N2 63 CO2 8 CO2 5.5 CO2 3.9 CO 2.5 CO 2.5 CO 9.0 H2 1.0 H2 4.0 H2 7.5 H2O 18.5 H2O 18.0 H2O 17.0 O2 0.0 O2 0.0 O2 0.0

Combustion of the fuel stream and air stream and sub-stoichiometric ratios lowers the adiabatic temperature of the combustion flame. Table 2 provides the adiabatic flame temperature at various Φ when the air stream is not pre-heated and then the air stream is pre-heated to 1,400° F.

TABLE 2 Without Air With Air Φ Preheating (° F.) Preheating (° F.) 1.0 3500 4100 1.3 3400 4000 1.5 2800 3400 2.0 2400 3000

Heat energy provided by the combustion flame is generally sufficient to produce steam at a desired temperature and quench the products of combustion. For example, some cracking processes using nozzle reactors (discussed in greater detail below) require steam at 1,200° F. At many of the temperatures provided in Table 2 above, sufficient heat energy will be available to both produce steam at 1,200° F. and quench the combustion products.

After injection of the air stream and the fuel stream, atomized water is injected into the combustion chamber and steam is formed. When the atomized water enters the combustion chamber, the heat energy provided by the combustion reaction between the air stream and the fuel stream converts the atomized water into steam. Thus produced, the steam can be used for various recovery and upgrading processing being carried out on the offshore platform.

The water injected into the combustion chamber can be obtained from any suitable source available at the offshore platform. The water may not require pretreatment, and therefore the source of the water is greatly expanded as compared to water sources that can be used when a boiler is used for steam generation. In some embodiments, seawater can be used as the source of water. In some embodiments where seawater is used, some pretreatment may be carried out, such as filtration to remove solids or desalination.

The water injected into the combustion chamber is atomized. Atomized water refers to small droplets of water that are part of fine spray injected into the combustion chamber. Any technique capable of atomizing water can be used. In some embodiments, atomization of the water and injection of the atomized water is performed by the same equipment. For example, high pressure atomizer nozzles can be used to both create an atomized water spray and inject the atomized water spray into the combustion chamber. With continued reference to FIG. 4, the combustor 200 can be equipped with such a high pressure atomizer nozzle 260. The atomizer nozzle 260 is in fluid communication with the combustion chamber 240 such that the atomized water can be injected into the combustion chamber where heat energy is available to create steam from the atomized water droplets. As shown in FIG. 4, in some embodiments the atomizer nozzle 260 is located near the periphery of the combustion chamber 240. In this manner, the atomized water can enter the combustion chamber 240 around the entire diameter of the combustion flame.

In some embodiments, the amount of atomized water injected into the combustion chamber is generally dependent on the amount of heat energy being produced inside the combustion chamber and available to convert the atomized water to steam. As noted above, some of the produced heat energy will be used to quench the other combustion products. In some embodiments, the atomized water is injected into the combustion chamber at a rate of from 0.5 to 1.5 times the fuel stream flow rate to be processed.

Other reactions occur in the combustion chamber as a result of injecting the atomized water into the combustion chamber and creating steam. For example, produced steam can react with unreacted fuel (e.g., methane) to produce H₂ and CO, which is an endothermic reaction. An exemplary reaction between steam and methane fuel is provided below:

CH4+H2O→CO+3H2, h=+206 kJ/mol

Carbon monoxide produced from this reaction with react with steam to undergo an exothermic water gas shift reaction. For example:

CO+H2O=CO+H2, h=−41 kJ/mol

Taking into consideration all of these possible reactions, the final products that can be produced in the combustion chamber as a result of the introduction of the air stream, the fuel stream, and atomized water into the combustion chamber include steam, H₂, CO, CO₂, and N₂. Each of these products can be used as motive fluids in the nozzle reactor cracking processes described in greater detail below.

The steam produced in the combustion chamber can be injected into a nozzle reactor along with injecting the collected hydrocarbon material into the nozzle reactor. An objective of injecting the two materials into the nozzle reactor is to crack the hydrocarbon material into lighter hydrocarbon compounds.

The combustion chamber of the combuster can be in fluid communication with the steam injection passage of the nozzle reactor such that the produced steam passes directly into the nozzle reactor. The steam exiting the combustion chamber and entering the nozzle reactor is passed through the cracking material injection passage where, as described above, the steam is accelerated to a supersonic speed. Any amount of steam necessary to crack hydrocarbon material injected into the nozzle reactor can be supplied into the nozzle reactor.

Other manners of providing steam can also be used. In some embodiments, a normal boiler can be used for steam generation, such as a stand alone or supplementary fuel fired boiler. In some embodiments, the exhaust from a turbine (such as the turbine exhaust described above) can be used in a tube and shell heat exchanger to heat water and create superheated steam suitable for use in the methods described herein.

In some embodiments, some deposits may appear within the nozzle reactor as a result of the upgrading process. Such scale build up should be monitored. In some embodiments, chemical treatment of the water prior to injection into the nozzle reactor can be provided in order to reduce or avoid scale build up. Any treatment processes capable of removing salts and other water impurities that could lead to scale build up from the water can be used, and include reverse osmosis, distillation, nanotechnolgy, and ion exchange.

Product exiting the nozzle reactor will include cracked hydrocarbons, including lighter hydrocarbon molecules than the hydrocarbon material injected into the nozzle reactor. The hydrocarbon material exiting the nozzle reactor will also have a lower viscosity than the hydrocarbon injected into the nozzle reactor. Accordingly, the product material leaving the nozzle reactor will have improved flow characteristics and will be easier and less costly to transport through pipelines back to shore. In some embodiments, the upgraded hydrocarbon material has a viscosity less than 380 cSt @ 15.5 deg C.

In some embodiments, preliminary separation of the products leaving the nozzle reactor can be carried out on the offshore platform. Any manner of separating the hydrocarbon product can be used. In some embodiments, cyclone separators are used. Cyclone separators can be useful due to their relatively small foot print. The hydrocarbon products can be separated into, for example, a lights, middle distillate, and residue stream. The residue stream may be recycled back into the nozzle reactor for further upgrading.

In step 1400, the upgraded hydrocarbon material will be transported back to shore through pipelines running from the offshore platform back to shore. In some embodiments, the ejection end of the nozzle reactor will be in fluid communication with the pipeline so that the upgraded hydrocarbon material leaving the nozzle reactor can be passed directly to the pipelines and be transported back to shore. Any suitable pipelines can be used to transport the upgraded material back to shore. In some embodiments, the piping will run along the floor of the body of water on which the offshore platform is position and extend from the offshore platform all the way to the shore. Once ashore, the upgraded hydrocarbon material can be subjected to further processing at a refinery. The upgraded hydrocarbon can be transported to the onshore refinery through a series of pipes that continue from the shore to the refinery, or the upgraded hydrocarbon material can be collected once it reaches land from the pipelines and transported via other means, such as through the use of trucks or trains.

With reference to FIG. 5, a system for offshore upgrading and transportation of extracted hydrocarbon material includes an offshore platform 500 located on a body of water 510 and above a deposit of hydrocarbon material 520 below the floor of the body of water. The offshore platform can include a nozzle reactor 501 and a combustor 502 to be used in the upgrading of the extracted hydrocarbon material. The system also includes pipelines 530 for transporting the upgraded hydrocarbon back to shore.

Offshore platform 500 can be similar or identical to the offshore platform described above in step 1000. Generally speaking, the offshore platform 500 is positioned over the deposit of hydrocarbon material 520 located below a body of water 510. The offshore platform 500 includes all of the necessary equipment to drill and establish production wells and extract bitumen from the deposit 520.

The nozzle reactor 501 and combustor 502 on the offshore platform are similar to the nozzle reactor and combustor described in greater detail above. In some embodiments, the production well will be in fluid communication with the material feed port of the nozzle reactor 501 so that extracted hydrocarbon material can be directly injected into the nozzle reactor for upgrading. The combustor 502 can also be in fluid communication with the nozzle reactor 501 so that steam generated in the combustor 502 can be directly injected into the nozzle reactor 501. In some embodiments where the combustor uses water from the body of water 510 for the production of steam, a pipeline can be established for transporting water from the body of water 510 directly to the combustor 502.

The pipeline 530 can be any type of pipeline suitable for transporting upgraded hydrocarbon material back to the shore. The pipeline 530 can be in fluid communication with the ejection end of the nozzle reactor 501 so that upgraded hydrocarbon material can be passed directly into the pipeline for transportation back to the shore. Pumps can be provided for moving the upgraded hydrocarbon material through the pipeline. In some embodiments, the pipeline will be laid along the floor of the body of water 510.

While the above described systems and methods generally reference use of a single nozzle reactor, multiple nozzle reactors can be used in the systems and methods described herein. The multiple nozzle reactors can be arranged in series, in parallel, or any combination of the two. Use of multiple nozzle reactors in series can generally help to increase the conversion of heavy hydrocarbon material into lighter hydrocarbon material, such as by separating heavy hydrocarbon exiting a first nozzle reactor and running it through a second nozzle reactor located downstream and whose operating conditions are adjusted to improve the conversion of heavy hydrocarbons. The use of multiple nozzle reactors in parallel can increase amount of hydrocarbon material that can be processed and can mitigate issues relating to scaling up nozzle reactors to handle larger capacities.

The above described systems and methods also generally refer to the use of steam as the cracking material. However, it is possible to use other cracking materials in the systems and methods described herein. For example, suitable cracking materials include natural gas, methanol, ethanol, ethane, propane, biodiesel, carbon monoxide, nitrogen, or combinations thereof. In some embodiments, these cracking materials can be heated in the combustor described above (e.g., where the cracking material is injected into the combustor instead of atomized water).

While the invention has been particularly shown and described with reference to a preferred embodiment thereof, it will be understood by those skilled in the art that various other changes in the form and details may be made without departing from the spirit and scope of the invention.

A presently preferred embodiment of the present invention and many of its improvements have been described with a degree of particularity. It should be understood that this description has been made by way of example, and that the invention is defined by the scope of the following claims. 

1. An offshore hydrocarbon material recovery and transportation method comprising: providing an offshore platform adapted for extracting hydrocarbon material from hydrocarbon deposits located below the floor of a body of water; extracting hydrocarbon material from a hydrocarbon deposit located below the floor of a body of water; collecting the extracted hydrocarbon material on the offshore platform; upgrading the collected hydrocarbon material on the offshore platform; and transporting the upgraded hydrocarbon material through pipelines.
 2. The offshore hydrocarbon material recovery and transportation method as claimed in claim 1, wherein the collected hydrocarbon material has a viscosity greater than 25000 cSt @ 20 deg C.
 3. The offshore hydrocarbon material recovery and transportation method as claimed in claim 1, wherein upgrading the collected hydrocarbon material comprises: injecting a stream of cracking material through a converging then diverging passage of a cracking material injector into a reaction chamber, wherein passing the cracking material through the converging then diverging passage accelerates the cracking material to supersonic speed; and injecting the collected hydrocarbon material into the reaction chamber adjacent to the cracking material injector and transverse to the stream of cracking material entering the reaction chamber from the cracking material injector and cracking the collected hydrocarbon material with the injection of the cracking material.
 4. The offshore hydrocarbon material recovery and transportation method as claimed in claim 3, wherein the collected hydrocarbon material injecting step includes injecting the collected hydrocarbon material into the reaction chamber annularly around the stream of cracking material.
 5. The offshore hydrocarbon material recovery and transportation method as claimed in claim 3, wherein the cracking material is a cracking gas.
 6. The offshore hydrocarbon material recovery and transportation method as claimed in claim 5, wherein the cracking gas comprises steam.
 7. The offshore hydrocarbon material recovery and transportation method as claimed in claim 3, wherein the collected hydrocarbon material comprises bitumen.
 8. The offshore hydrocarbon material recovery and transportation method as claimed in claim 6, wherein the steam is generated by a method comprising: injecting an air stream and a fuel stream into a combustor and producing a combustion flame in a combustion chamber; and injecting atomized water into the combustion chamber and forming steam.
 9. The offshore hydrocarbon material recovery and transportation method as claimed in claim 1, wherein the upgraded hydrocarbon material has a viscosity lower than 380 cSt @ 15.5 deg C.
 10. A offshore hydrocarbon material recovery and transportation system comprising: an offshore platform established over a body of water; and a nozzle reactor established on the offshore platform.
 11. The offshore hydrocarbon material recovery and transportation system as claimed in claim 10, further comprising: upgraded hydrocarbon material transportation piping extending from the offshore platform to land surrounding the body of water.
 12. The offshore hydrocarbon material recovery and transportation system as claimed in claim 10, further comprising: a combustor adaptable for generating steam to be used in the nozzle reactor.
 13. The offshore hydrocarbon material recovery and transportation system as claimed in claim 10, wherein the nozzle reactor comprises: a reactor body having a reactor body passage with an injection end and an ejection end; a first material injector having a first material injection passage and being mounted in the nozzle reactor in material injecting communication with the injection end of the reactor body passage, the first material injection passage having (a) an enlarged volume injection section, an enlarged volume ejection section, and a reduced volume mid-section intermediate the enlarged volume injection section and enlarged volume ejection section, (b) a material injection end in material injecting communication with the combustion chamber, and (c) a material ejection end in material injecting communication with the reactor body passage; and a second material feed port penetrating the reactor body and being (a) adjacent to the material ejection end of the first material injection passage and (b) transverse to a first material injection passage axis extending from the material injection end to the material ejection end in the first material injection passage in the first material injector. 